Diamondback Energy, Inc. (FANG) Q3 2026 Earnings Call Transcript

Good day, and thank you for standing by. Welcome to Diamondback Energy third quarter 2026 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you'll need to press star 101 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 101 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Wallis, VP of Investor Relations. Please go ahead.

Thank you, Stephen. Good morning, and welcome to Diamondback Energy's third quarter 2026 conference call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing DynaVac today are Case Van Tonk, CEO, Danny Wesson, COO, Jerry Thompson, CFO, and Al Barkman, Chief Engineer. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's findings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Case.

Thank you, Adam. I hope everybody read our much longer shareholder letter last night. A couple key mega themes we've been thinking about a lot in the Permian, but also, you know, our regular update on the business. So I think we'll just go straight into Q&A, and operator, please open the line for questions.

All right. Thank you. At this time, we will conduct a question and answer session. As a reminder to ask a question, please press star 1-1. Our first question comes from the line of Neil Dingman of William Blair. Your line is now open.

Good morning, Kay's team. Nice quarter. Kay's my first question just on your reinvestment rate specifically. Just, you know, as you were wondering, do you all think about sort of maybe capital allocation, perhaps even when you give your growth plans differently, given your leading 30% reinvestment rate? I mean, given how low that is, I'm just wondering, you know, what, how that changes in your thought process when you all are setting the plans.

Yeah, Neil, I mean, you know, I think there's two big pieces of capital allocation within Diamondback. You know, first is let's drill our best stuff first, right? We've been very good at that. We spend a lot of time finding the best projects in our portfolio, and, you know, that is the baseline for, you know, the capital plan and the output that is, you know, the free cash and the reinvestment rate. You know, I would say on the reinvestment rate side, you know, it's interesting. I mean, Diamondback, you know, 32%. I think it stripped yesterday. It was a 30% reinvestment rate for the year. You know, that's below super majors, and the super majors have refining and crack spreads that are at all-time highs. So I think, you know, an E&P investor from 2018 or 2019 would fall out of their chair seeing an oil and gas company, E&P shale company, you know, reinvest at sub 30, you know, 32%. So we're very, very proud of that. That's a combination of, one, that capital allocation in the field, you know, two, the lowest cost structure in the basin that we're continuing to drive down. But then three, you know, we know that the market is volatile. We know that, you know, front month commodity prices have been all over the place throughout this year. I think, you know, we saw a $60 a barrel swing in Q3 alone. And so, you know, our best protection is to keep that reinvestment rate low, generate a ton of free cash, and then allocate that free cash appropriately to what the market's giving us. And, you know, I would expect that reinvestment rate to stay low, capital discipline to remain, and, you know, us to allocate that free cash to the right side of the balance sheet.

No, it makes a lot of sense. And then just my second question, maybe a little more qualitative, just, you know, we get asked a lot on the, you know, maybe Stephen's family, specifically with the Stephen's family case, can you talk about your or even Diamondbacks' relationship with the family?

Yeah, I think we have a great relationship with the family across the board and the team personally. I think anytime you have a shareholder that owns that many shares, they deserve all the attention that they need. We go see them every quarter and talk to them. Obviously, they have sold down a good amount of shares this year, and we recognize that that sometimes weighs on the shares, And we've tried to support, you know, buying back shares in the aftermarket. But at the end of the day, you know, the family is a long-term believer in this story. You know, that's why they did the deal with us. You know, I think if you look at the success of the Endeavor transaction, you know, none of us would take that back. But I do think one thing, you know, we talked a little bit about governance in the shareholder letter. And, you know, just like within Diamondback, you know, we're kind of beyond talking about legacy Endeavor and legacy Diamondback. We're kind of one, you know, we're one team rowing forward here in Midland, Texas. You know, the same goes for our board, and, you know, we now have an 11-person board. Two members are technically designated by the family, nine, you know, not, but at the end of the day, that's just one board now, you know, moving forward. So we're happy with the size of the board. We're happy with the family, and I think the feeling's mutual.

Great comment.

Thanks, Neil.

Thank you. Our next question comes from the line of Neil Mattaw of Goldman Sachs. Your line is now open.

Yeah, good morning, Kate and team, and thanks for these three mega themes. I think it gives us stuff to key off of this morning. I just wanted to spend some time on improving recovery. So you indicated you're at about a 10% of the oil in place is being extracted today. You know, Kate, how do you see that evolving over time? And you talked about some of the components you talked about in the letter around development, completion, and EOR. And then as you kind of tie that into the Permian, the Permian's producing, call it 6.7 million barrels a day, so about half of America's oil production here today. How do you think about the growth of the basin broadly in that context?

Yeah, Neil, that's a great question. And, you know, I think the key is, you know, some of these things that, you know, were probably more theory in the last couple years are becoming reality. And, you know, we're big believers in stacking up the little wins here at Diamondback. You know, if you think about what we've done mechanically above ground, you know, drilling wells starting at 30 or 40 days, now we're at, you know, four or five days, you know, that didn't happen overnight. And I think, you know, the theme on improving recoveries isn't going to happen overnight, but if we're thinking about the 2030s and beyond, you know, there are some things that are being tested in the field that are starting to look like, you know, successes. And, you know, I think the completion technology continues to improve. I think we're able to sense more and see more down the hole than we used to. But then you also have some things like surfactants or chemical EOR that, you know, are starting to have some positive use cases, whether it's on the front end in the completion or in the remedial jobs that we've been trying over the last year and a half, two years. And we're starting to learn a lot more about it and, you know, improve our process and move from a theoretical process to something we can model. And I think, you know, that should, you know, if you go to your macro comment, that should either allow the basin to grow more or be able to do this longer. And, you know, one of the key points of the mega themes that we put out there is that, you know, we're not just thinking about Diamondback for the fourth quarter or for 2027. You know, we're thinking about Diamondback for the 2030s and this basin for the 2030s. And, you know, I think spending capital and time and intellectual capital today is going to be rewarding for our shareholders for the long term.

Now, it was interesting that the letter kind of really focused in on the Permian and your confidence into the next decade, because one of the questions we often get from your investors is, should Diamondback diversify beyond the Permian? But I'd love your perspective on this, because you kind of are at a fork in the road as it relates to that. Is this kind of indicating that you want to stay at Permian Pure Play?

Yeah, I mean, listen, you know, we want to know what productivity returns. And, you know, we have looked and seen, you know, plays that get attention, whether it be in Canada, you know, shale plays in Argentina, you know, some of the international stuff starting to get attention. And I kind of go back to my golden rule, which is no, you don't know. And, you know, I do know that Diamondback is a basin expert. You know, we spend every day, 1,700 people spend every day trying to get better at what we do in the Permian Basin, and we don't spend a lot of time thinking about other places outside the basin. Now, with the mega themes, I think that means, you know, there are other avenues to grow the business throughout the basin, like our mineral business, you know, some of the stuff we're doing on the midstream side, obviously the infrastructure data center wave, you know, we think we can kind of be at the center of that and add value to that process. But at the end of the day, I think our investors would rather us spend the extra $100 million on surfactant tests to improve our overall recoveries and duration than, you know, go explore outside the basin that we don't know as well. And I think that core competency should result in, you know, continued long-term outperformance. Thanks, Neil.

Thank you. Thank you. Our next question comes from the line of David Dekelbaum of Stiefel. Your line is now open.

Thanks, Kaze and team. I appreciate you guys taking my questions. I was hoping just for this year, you guys kind of guided towards the higher end of capital guidance. It looked like there's some cycle time improvements and perhaps a little bit of added activity. Your comments were that well-cost inflation is roughly being offset heading into next year, that you're at least asking your team with trying to offset well-cost inflation with efficiencies. I guess as we think about that billion and change level for 4Q, is that a reasonable starting point as we think about 27 and still obtaining that kind of single-digit growth number?

Yeah, David, I'll give you some high level, and then Danny will give you what he's seen in the field. You know, I think, you know, we've kind of implied last quarter that we were starting to see some inflation on the consumable side of the business. You know, we're basically guiding the same CapEx in Q4 as essentially Q3. We ended up in Q3. You know, we think that we can probably, you know, hold oil production flat at the higher end of that range going forward And, you know, fight off some inflation with efficiencies, you know. But I think if we want to grow next year, which is, you know, still very much TBD based on the macro, you know, we have to spend a little more than the range that we put out for Q4. And, you know, I don't know, Danny, you want to talk about what you're seeing?

Yeah, I mean, I think we, you know, we're price takers, right? And we've said that before, but, you know, our focus has always been on controlling what we can control and, you know, fighting the variable costs, you know, day in and day out and trying to do that better than everybody else. And, you know, we always look for value, whether that's execution value or value in our procurement strategy and what our service partners can bring us, differential to anybody else. And, you know, we're going to continue to do that through 27. If there's an inflation cycle, which, you know, as at $100 oil, you can expect that there's going to be probably an inflation cycle that comes through on the service side. You know, we're going to do what Dimeback's always done and fight the variable cost side of that and, you know, look for ways to offset some of that through execution or, you know, business relationships. But, you know, it's to be determined yet on what 2027 is going to look like with regards to the service sector and the inflation that's coming through. You know, I think there's a lot of volatility in the marketplace today. You know, we'll kind of see what happens post what's going on today in the U.S. and, you know, throughout the end of the fourth quarter. And, you know, look forward to updating you guys early next year.

I appreciate that, Danny. Perhaps we can talk about the Barnett a little bit. You guys showcase some pretty impressive results, particularly in and around that Spanish Trail area. I am curious, as we think about 27 and beyond, you know, when does the Barnett become, you know, more of a development-oriented program versus HBP, or should we think about 27 as more of satisfying HBP commitments on the Barnett side before really endeavoring to high-grade where activity goes?

Yeah, so, you know, it dawned on me that we hadn't updated the market on some of our best results to date in the Barnett. You know, we're still trying to lease around those areas, you know, and obviously, you know, us releasing these wells now today is going to bring a lot of attention to those areas. You know, fortunately, we've, you know, gotten as much acreage, almost as much acreage as we can, although the play continues to grow. And I would just say, you know, what was once a geologic success is now, you know, turning into meaningful value for the company. And we're moving into kind of full-field development, and Al, I don't know if you want to give some color on what we're up to in Q4 and next year.

Yeah, David, that's, you know, when you look at slide 11 there in the deck, we provided a locator map on the bottom right to kind of go along with the well results that we released. And, you know, what I would say is we do have some obligation drilling coming up in 27. Most of that obligation drilling is focused in and around where we released these well results. So the stars that you're seeing kind of on the western side of the basin. And so what we're doing is we're leaning into sort of the co-development in those areas just because the returns and the well performance are real I appreciate the call, guys.

Thank you. Our next question comes from the line of Jeffrey Lambuhon of TPH Research. Your line is now open.

Good morning, guys, and thanks for taking my questions. Maybe just to follow up on the Barnett commentary, as you make that move from delineation to full field development that you talked about, can you talk about what's going to change from an on-the-ground operational perspective as it relates to well costs? You know, which items are you focused on, whether it's pad size, lateral length, shared facilities, what have you, and which of those do you see moving the needle most towards that well-cost target for the program?

You know, I think it's all of the above. Obviously, that lateral length is, you know, the biggest knob we can turn on the dollar per foot basis, just moving that denominator longer, and, you know, we intend to utilize the lessons we've learned in the shallow development and exploit those things into the deep development to drill longer laterals, you know, shared infrastructure across the surface. Acreage will benefit on the infrastructure capital that you need to deploy to develop those deep zones. And then, you know, just generally when I look at what is going on, and we're really early still in, you know, the development phase of the deep zones, But when I look at what's going on from the drilling group, you can see, you know, marked improvements in every whole section there, whether it's, you know, getting our intermediate strings to bottom faster or drilling the curve faster, ROP in the lateral. It's getting, everything's getting a little bit faster. So, you know, I continue to expect that, you know, on a life for life well that we'll see, you know, efficiencies continue to accrue to us in those deep horizons. It's just hard to talk about it today because we just don't have a whole lot of data set, a big data set to look at. But I can tell you that it is looking better, you know, quarter over quarter.

Perfect. That makes sense. And then for my follow-up, I just wanted to focus on some of those avenues to grow the business while focusing in the Permian that you mentioned. First, on some of the gas and LNG commentary, as you think about the path forward for diving back and controlling more molecules downstream on this front, as you think about doing business with those potential counterparties, what's a good deal look like for you guys in your view, whether you can speak term, price linkages, or volume commitments, and then kind of similar line of Questioning on the power side. On the first project, how are you feeling about the gating items to FID and is there anything you can share just on latest discussions around that?

Best deals across the board for Diamondback shareholders. I think, you know, on the LNG side, you know, shareholders have not owned Diamondback to date to, you know, be the tip of the spear in taking on 15 plus year commitments to get LNG facilities built. But I think as we've studied the You have a lot of LNG demand and maybe some question marks on where the supply is going to come from. And you have a lot of counterparties that have taken out a lot of space that are long offtake and short molecules. And we're obviously very long molecules and I think likely to be longer gas molecules over the next, you know, five, ten years. And so, you know, we've taken out a lot of space on pipelines to get to these, you know, closer to the end markets and start to have real conversations with, you know, the large players in the LNG space. And, you know, I think there's win-wins. You know, I think we have to explore what those could be. We tend to be able to get deals done. But I do think, you know, it's interesting. There's a lot of LNG players that have taken out even space on some of the pipelines that we're on that don't have the gas supply. So I think, you know, generally we said it in a letter, you know, the basin moving from supply push to demand pull, whether it be power or LNG, should be a good thing for the owner of the molecule long term. And, you know, when it comes to our power project, I'll let Jerry give an update, and then I can say some high-level things. Yeah, I mean, I think the biggest thing, like you mentioned last quarter, is we're close. We've got a unique project on Bryan Ranch that is shovel-ready. We've remediated the land, we've secured the equipment, and we've got water and gas teed up and ready to go. So we're really just dotting the I's, crossing the T's on final agreements, but very excited that we are in this position and feel

like we should be able to talk more about it soon.

Yeah, I think I'll just add to what I've learned from a macro perspective, and this is why we put it in the letter, you know, assuming a friendly Texas regulatory environment, you know, Texas has a chance to continue to grow its economy significantly through the development of this infrastructure. And a company like Diamondback out in West Texas, you know, can aid in that process, whether it's, you know, we own surface, we control gas, we can work with midstream partners to get to sites, we have a good idea on site selection, and I think we can figure out ways to get deals done and make things move faster than they have to date. And, you know, if you talk to the tech world, they move pretty fast, but, you know, DinoVac's moved pretty fast over the last 15 years, too. So I think there's a natural intersection there. I think we have a role to play. I think, you know, for our investors, they need to know that, you know, we're still going to stay in our lane on what we're good at, but be able to get things across the finish line. And I think, you know, just from a Midland and from a West Texas and an employment perspective, you know, a lot of fears about AI and automation in the oil field and what that's going to do for employment. And, you know, part of the message in that mega theme is, you know, this could be the next wave of continued GDP growth in this region, as well as, you know, a higher paying employee base that, you know, gets retrained to, you know, work on some of these projects. And, for instance, you know, Diamondback put a million dollars into Midland College to form a new program for the electrical side of the business. And, you know, I think that's important, and I think the community should realize that, you know, we've got a lot left to do, and there's going to be decades of growth ahead of us, and it just might look a little different than, you know, the last 10 years of shale development.

Perfect. That was great, guys. Sounds like a lot of all-around good there. I really appreciate the detail, and we're looking forward to hearing more on all those fronts.

Our next question comes from the line of Bob Brackett of Bernstein Research. Your line is now open.

Good morning. Following up on the gas commentary, I guess these are mega themes. These are not spot market updates. Can you talk about the time horizon over which you see this potential demand pull or the market being short of physical molecules? Are we thinking 2030, mid-2030s, not next month?

I don't think it's next month, Bob. You're very, your observation. But, you know, I think, you know, we've become a much larger company that has had to start thinking about, you know, downstream markets and end markets versus, you know, where the next well is going to get drilled. And, you know, I think, you know, part of the reason we discussed this is obviously, you know, we committed to a good amount of production to Solitude. You know, that project got off the ground and funded, you know, within a couple months. So it kind of just shows that, you know, the supply is going to be there, but also, you know, the people that are taking out space on the other side of these pipes are also, you know, looking for supply, too. So, you know, we've looked at kind of all the U.S. basins, and, you know, it's interesting to see what Toby and Jeremy and EQT are talking about in the northeast and demand increasing up there. I think we see the same in Texas, and obviously the LNG is all announced. So, you know, the gas has to come from somewhere, and if you can't build from the northeast down south and the Haynesville can't, you know, meet these 10, 20, 25 Bs of demand, you know, it's got to come from the Permian. And I think that, you know, we kind of see that coming, obviously not next month, but during periods of time over the next decade where Permian gas is going to increase in value.

Very clear. Quick follow-up. On the Barnett wells you disclosed on the recent results, they look like they're all sitting in the deepest part of the basin or the greatest depth down to the top of the Barnett. Is that for a reason? Do you think that that horizon works as you move toward the shelf edge?

You know, this is one of the deeper parts of the basin. You know, there are some maybe slightly deeper parts as you kind of move to the north. But overall, yeah. You know, I think it's the combination of the resource quality that we've got in this area and the deeper, you know, higher bottom hole pressure that's helping us with the higher rates. And I think part of the reasoning behind where we put our acreage position together over the past four or five years is we knew where the resource was the thickest and going to be the best, and that's why we put together the leasing program in areas that we did, and we're maybe a little coy with the well performance up until today.

Very clear. Thank you.

Thank you. Our next question comes from the line of Josh Silverstein of UBS. Your line is now open.

Yeah, thanks. Good morning, guys. A lot of focus on debt reduction over the past year, you know, on the consolidated basis. You're down about $4 billion. Is the idea to keep using this stronger oil price environment to your advantage on the balance sheet to try to save, you know, Capacity for the buybacks, you know, when and if, you know, oil prices do decline?

Yeah, I mean, I think in the simplest way, that's what we're trying to do. You know, obviously, opportunities come up, investments come up, you know, having the balance sheet to be able to do that without, you know, impacting long-term shareholder returns is a good place to be. I would say, you know, but with the free cash that we're generating kind of quarter in, We're really just trying to take what the market gives us. And obviously, we talked about Q3, a $60 swing in oil price. Well, in July, when we had oil price weakness, we bought back shares. In August, we paid our dividend. And in September, we saw weakness at the end of the quarter again and bought back shares. And then here we are early October, we had kind of rates blow out. Okay, market's given us long-dated bonds well below par, so we lean in and buy back bonds. So, you know, really just trying to make the right capital allocation decision every day, you know, with the number one decision we made, you know, continuing to increase the base dividend, you know, still well-protected below $40 a barrel oil price. You know, I think there's still room for that to grow, and as the balance sheet strengthens, it should naturally grow. But, you know, also having the balance sheet capacity to do what is, in my mind, the holy grail of an E&P, which is lean on your balance sheet to buy back shares, you know, at the right point in the cycle. And, you know, we're clearly not at that point today. I hope we never get there, but I think we're prepared for anything with this, you know, free cash wave coming to Diamondback shareholders.

Got it. Thanks. Thanks. And then one for me on just on the data center, you know, milestones. You know, I was curious, you know, when and if you're taking power generation capacity. And I was also kind of curious how you might be able to use Viper as part of this as well, given maybe a different cost of capital there or some drop-down opportunity. Seems like that would be certainly an interesting opportunity for you guys.

Yeah, I think, you know, the projects and the projects in this basin have kind of moved to the mobile power, you know, side of things just to get power as quickly as possible, so I think you can expect that from us and what we're trying to do out here. Obviously, I don't know if that's the long-term solution, but I do think there's going to be ways to grow these projects over time, you know, with more long-term power solutions, given the amount of gas that we have out here. And then, you know, on the Viper question, I think that's interesting. You know, I think we could debate if Viper has a lower cost of capital right now than Diamondback. I think the market hasn't rewarded Viper as much as it should have this year. But I think, you know, first and foremost, we've got to get this project signed up, and then how we monetize that is tomorrow's discussion.

Thank you. Our next question comes from the line of John Freeman of Raymond James. Your line is now open.

Yeah, good morning. Thank you. I believe in the Barnett, y'all recently started flowing back your initial kind of full-section development there. Should we sort of think of it as like maybe when you get more fulsome results on that, maybe sometime first half 27, is that sort of the main sort of determinant at this point on whether that kind of five rig kind of activity kind of run rate potentially would accelerate? I mean, obviously, the costs are already doing a really good job of kind of on a leading edge, already kind of getting around that 800-a-foot target. So is it more just trying to get an understanding of what it looks like on a full-section development basis?

Yeah, John, I mean, it's flowing back right now, and it looks good early time. So, you know, nothing that scares me or scares the team from continuing to push on. You know, I think we have four or five full-section developments coming on over the next three or four months. So, you know, we're happy to update the market on that and the performance. I think as you see in Al's slide 11, you know, the individual wells are obviously well above the average, and, you know, we're not going to model a type curve that's the, you know, the best parent well in the basin. So I think there's room for improvement on, you know, full section development overall relative to that type curve as well as the cost side. And I think, you know, the key message here is, again, And the geologic success is actually turning into a lot of value for our shareholders here.

That's great. And then just one more follow-up also on the Barnett. I believe one of the other things y'all have looked at is potentially being able to lower the cost per foot fairly meaningfully is maybe looking at reducing the completion intensity, maybe something somewhere closer to the kind of core Wolfberry design. Is that anything that y'all have done any pilots on yet, or just that's in the future?

Yeah, let me give you the simple answer is, you know, early on in these developments, we kind of gold-plate everything and then start to work our way down, and Danny can kind of give you some color on some things we're thinking about.

Yeah, I mean, I think that's a great question. It's something we certainly are looking at. I think, like Kay said, we don't want to undercapitalize these first, you know, delineation of full section development, so, you know, we're trying to make sure we have a sufficient completion that we're not, you know, questioning whether something was completion-driven in the results. I think, you know, as we get further into development mode, we'll start looking at what's the right size jobs for, you know, the spacing that we're developing the section at, and, you know, these are going to be wider spaced wells than what you'd see in our core development, so I wouldn't expect, you know, to see the job sizes in line with what we pumped in, like, a spray berry well, but, you know, you might see us, you know, tailor it back some, or look, it could even Thanks, guys.

Appreciate it.

Thanks, John.

Thank you. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open.

Yeah, good morning. Thanks. I was wondering, Casey, you appear to be a bit cautious on 2027. Just give us a sense of like, you know, is there something you worry about on the oil price? And you've got the inventory, you clearly have the execution and capabilities to grow in this high price market. And we do have like a 24 month curve that's above your mid cycle price. So can you just give us, you know, the way you think about, like, the future in the next couple years for Dimeback and why you think, like, you know, a starting point is kind of flattish growth with, you know, potentially some, you know, minimal growth upside?

Yeah, I wouldn't say I'm necessarily cautious personally, but I think it's always good to prepare the company for, you know, a swing to the downside. You know, it's never – it's not a good way to run an E&P just to be, you know, a permable. So I would say, you know, given what we've seen in terms of global inventories, in terms of shipping rates, in terms of what we've seen on the shuttle trade and how much we're spending to get ships through the strait and, you know, the overall geopolitical instability, I'm probably more in the hire-for-longer camp personally. But we prepare the business to keep our cost structure low and execution, you know, in perfect shape because, you know, the inevitable can happen. And I think, you know, 2026 is a great example of that. You had, you know, every analyst calling for 55 or lower oil, and, you know, we've averaged 95. So I think we're just, you know, we've always prepared our business for a lower price environment. We've always kind of shined in a lower-priced environment, but, you know, I think there's just still some uncertainty over the next couple months, and there's just not a need for us to put out a formal 2027 plan because we always end up doing that in February, and that's, you know, that's where my head's at and the board's head's at.

Okay, understood. And just a follow-up question. My follow-up question is on the Solitude pipeline. You know, as we start thinking about, like, capital spend over the next year or two for Diamondback, do projects like this, where does that capital ultimately fall? Is that going to be part of the budget, or does that sort of, you know, fall into some sort of an equity affiliates?

Yeah, so I'll give my high-level thoughts. I think it's going to roll through the equity affiliates, and you think about Diamondback this year, and I've given this stat out a lot this last quarter. Diamondback corporate is going to pay $2 billion or nearly $2 billion of cash taxes this year in a U.S. market that's only going to pay $400 billion of cash taxes to the government. So, you know, we're half a percent of the cash tax spend in the country this year, which is a wild statement. And that's why we're kind of implying, you know, an investment in something like Solitude, you know, investment in PowerGen and the Basin, you know, these can be really good investments for Diamondback shareholders and, you know, outside the traditional CapEx budget, but that also, you know, defers some taxes over here because we are paying a lot of taxes at Diamondback.

Understood. I think a lot of us have that same problem.

Agreed.

Thank you. Our next question comes from the line of Philip Youngworth of BMO. Your line is now open.

Thanks. Good morning, guys. Slide 10 is always great, and you added an NPV per section graph here. I was hoping you could just explain the developed versus undeveloped part where Diamondbacks 89 percent, And just because it's maybe not intuitive why FANG is so much higher than piers in the low 60s when wells per section average zones aren't terribly different, and you have another pier that's a bit more comparable to you with fewer zones targeted. And also, just why don't you think piers can kind of replicate what you're doing here on the development side design, or maybe it's just acreage quality or just how properties were developed historically?

In my mind, it's the most important slide of the deck and probably the most misunderstood slide on the investor side. So I'm glad you're bringing it up. You know, I think high level, you know, all of our equities have the implied value of our production and the implied value of the upside and the undeveloped inventory that we have to prosecute, of which Diamondback has a significant amount. I think what that slide is proving is we're proving that that upside is translated to cash flow that goes into your pocket, whereas some peers have implied upside that remains at risk to be developed. And that's the, you know, parent-child issues, you know, throughout the basin. You know, and then, you know, the last point I'll say, and Al can give you the details, is, you know, it proves that an acre in our hands is worth more than an acre in someone else's. And that's been the key to Diamondback's success to date. Great question, Philip.

The only thing I would add there is, you know, I think at a high level, the way to think about that chart that's on the right-hand side, the full bar is effectively the ideal. The centralized value of the DSUs that were analyzed for this chart, and the dark red that fills up that full bar, that's the PV that was captured during the development of those DSUs. And so, you know, like Kate is saying there, effectively through the way that we develop, the way that we target these wells, and via our cost structure, we're able to capture 90 percent of the idealized value of the DSUs, whereas, you know, a similar peer, peer three that's right below us, has similar acreage quality, but are only capturing 61 percent of the total value of the DSUs. DSUs. Now, that 39% is remaining value, but, you know, like we mentioned, that value is exposed to degradation risk when you return to the DSUs and deal with parent-child overfill, underfill-type development.

Yeah, that's great detail. And yeah, we have noticed your wealth productivity is higher this year, which is not a broad-based trend we see across the basin. But the second question is, I thought it was interesting that 79% of Vipers' capital had been deployed to proprietary or off-market deals, and the Gowoy Ranch purchase was pretty significant. I was just hoping you could expand on the go-forward opportunity set for minerals, just because it seems like a real advantage for Diamondback. I assume we don't see this in the traditional EMP space. And just while we're on the topic, can you just touch on how you see M&A for Diamondback now, recognizing you're good at it with a long track record, but we're also above mid-cycle as far as commodity prices?

Yeah, I would say Diamondback's ground game is just probably not as large relative to the size of the enterprise. But, you know, and so we're going to continue that going forward. I do agree with you, you know, M&A is tough in this type of volatility, especially, you know, the front month volatility. So, you know, I'm probably, you know, particularly, you know, public-to-public or large-scale M&A seems harder to get done in this environment than easier. On the Viper side, you know, the alternative is, you know, Viper has a balance sheet that was able to do a deal like the McElroy Ranch with cash, and that's where I think, you know, we differentiate ourselves on the Viper side. And I think, you know, if you look at, like, how we've been looking at those deals, you know, the front month may be high, back into the curves below 70, you can kind of run a scenario at 70, $75 crude and generate a reasonable NAV rate of return. So that's kind of how we're thinking about it at both companies. Obviously, I think the opportunity set has been brighter at Viper, and we've kind of used the Viper balance sheet to get some significant deals done over the course of this year.

That's great. Thank you.

Thank you.

Thank you.

Our next question comes from the line of Derek Whitfield of Texas Capital. Your line is now open.

Good morning, guys, and thanks for taking my questions. Thanks, Derek. I wanted to start with AI for my first question. As you think about what you've accomplished with autonomous lift and preventive maintenance initiatives, how would you characterize where the organization is along the AI machine learning adoption curve generally, and how would you quantify the upside you see associated with adoption in both development and production?

Yeah, so I'll start with kind of the company AI strategy and then give it to Chad to talk about some of the successes in the field. You know, I kind of put the AI thesis or strategy at Diamondback in three buckets. You know, the first is kind of the table stakes bucket of, you know, higher productivity per employee, you know, menial tasks getting automated and, And, you know, taking – making employees have more free time to, you know, do their work versus accomplished tasks. You know, and that's happening across the board. I think the field is kind of the second – the production side of the business is where we're starting to see real benefits of AI and automation today. Chad's going to talk about that. And then, you know, I think the holy grail, which we have, you know, some very smart people working on is, you know, how can AI impact the subsurface and productivity? And whether that's completion design, completion technology, you know, subsurface evaluation, you know, all of that, you know, could be the, you know, the billion or multi-billion dollar wins on the AI side. But Chad's seen some wins in the field. He's going to talk about a couple of them.

Deployment of AI, and when you think about our production offer, we've been focusing on the self-optimizing of our artificial lifts. We put an example in the notes about plunger lift, really the success we're seeing there, because the deployment there is working really, really well. Those are totally autonomous, self-optimizing solutions, and yielding both a savings in terms of manpower and the amount of compression that we're using in that solution. So we're just carrying that board across every form of artificial lift that we have out there and seeing a lot of success with the various trials and then you leverage that into how we use our people and we also put an example in there where we're moving into some drone technology that we can ultimately move our folks from having to go hunt for issues in the field to we identify those up front and we deploy them to go fix them. Great.

Sounds exciting, guys. Case, I wanted to come back to EOR with my follow-up. If your base recovery is 10%, how much incremental recovery could surfactants add? Is it another 1% to 2%? And another question, just to make sure I understand the distinction or difference, perhaps, is there a difference between the surfactants that you guys are talking about and what we're hearing from Chevron with advanced chemicals?

Yeah, Derek, great, great question, man. You know, I think it's, you know, we test a lot of chemicals in the lab with core and fluids that are from the reservoir. You know, some of the results that you get in the lab work are pretty impressive, right? But, you know, I think the thing that we're excited about is even a, you know, even a 1% to 2% uplift in recovery factor, you know, would represent a 50,000 to 100,000 barrel per well uplift, which is, you know, would obviously be very meaningful to Diamondback. So, yeah, I think that's sort of TBD on that, and in terms of the chemicals that we're testing, we've tried in the lab, trialed a lot of different chemicals, chemicals that are very similar to what other operators are doing, some things that we're doing recently that, you know, are sort of more in-house developed, and, you know, we're really excited about those as well. So, you know, we're kind of across the board. I think, like we mentioned in the known, there's a lot of variability in the results. And so, you know, we're trying to hone in on the specific, you know, chemical compositions that work, the different techniques, how we deploy them in the field. And so there's a lot of variables remaining for us to optimize. But overall, I think just, you know, being early innings, we're very excited about the results that we're seeing.

Yeah, I think one thing from a strategy perspective, you know, we've highlighted this group. We've created a new group within Diamondback. They get a lot of airtime with us. They're getting a lot of capital to try things because I think, you know, again, it's going to be important, and it's going to improve not only productivity but also longevity.

Great update, guys.

Thank you.

Our next question comes from the line of Doug Liggett of Wolf Research. Your line is to open.

Thanks for having me on, guys. Case, I wonder if I could come back to the barnet. The productivity, obviously, the hourly productivity looks pretty impressive. The capital is moving in the right direction. I'm trying to understand, at what point do you get to full field development to the point where your sustaining capital directionally moves either up or down as that mix changes. In other words, better productivity, but more expensive wells. What does that mean for your sustaining capital when the barnet is a permanent part of the mix?

Well, I think as the costs come down, Doug, and the NPV per well is higher than the base plan, And as that works through the system, if we keep improving results, which, you know, I expect and I think you would expect, you know, that should improve sustaining capital or on a push basis, it should extend our ability to maintain sustaining capital, you know, around where it is today. So that's kind of how I would frame it. Ali, have you anything to add there?

Yeah, Doug, I think, you know, when you look at slide 11 here, and we show some equivalencies on rate of return, NPV, and just kind of gross capital efficiency, you know, I think the balance and one thing to keep in mind here is these are idealized analyses, right? And so we're using sort of base assumptions of 100% working interest and one quarter royalty to do this analysis. We've got areas across the basin, right, where we own minerals that are going to make those developments look more advantaged. There are areas that are going to be high graded that we know we see a little better well performance, right? So, you know, I think sort of the target that I would look at specifically to your question, you know, once we get to the $900, kind of $850 to $900 range on a dollar per foot basis, that's really where you see those kind of metrics of the 12 to 18 month gross capital efficiency rate of return, and then PV is already well in excess of the core program. So, you know, we know the resources there in the co-developed sort of initial phases. We see costs kind of in the $900 a foot range, and that's without any of the efficiencies that Danny mentioned previously. So, you know, we're very excited about the program. There are going to be areas that compete for capital today.

That's helpful. Sounds like less wells for the same result, basically. So good for capital efficiency is a punchline, it sounds like. I guess my follow-up is a quick accounting question. Obviously, pretty elevated oil prices, little deferred tax. Are you now in a full cash tax position? Should we think of that as being the case on a go-forward basis?

We've been there for years now, and I think we've been paying a much higher overall tax rate for a while. I think they're all going to have to catch up and have to live with our world of higher cash taxes. But, yeah, we're paying our fair share, Doug.

All right. Fair point. Financials.

Thank you.

Thank you. Our next question comes from the line of Kevin McCurdy of Pickering. Please go ahead.

Hey, thanks for taking my question. Maybe coming back to the mega theme on gas, you obviously are going to get a cash flow benefit from higher Waha prices, but are there any operational inventory uplifts from the higher gas prices? Maybe are there parts of your acreage program that you haven't drilled due to the prices, which may be in the drilling queue in coming years?

It just hasn't been something we've had to or tried to drill to date. So, you know, I think that you're going to see across the basin, you know, a lot higher gas cuts in certain zones, in certain areas. And, you know, we have some of it. We just haven't had to drill it yet.

Okay, that's fair. And then it looks like to us that OpEx was the driver of the EBIT for the quarter. You talked a little bit about the LOE earlier, but maybe on the GP&T side, what was driving the lower guidance there?

Between your gas realization and your GPT, you know, cost, depending on how much gas we take in kind. So I would say, you know, the beat that we're most focused on is the stuff we can control, which is LOE. LOE, but on the GPT side, it's really just a mix between realizations and how much GPT you pay.

I appreciate it. Thanks, Keith.

Thanks, Kevin.

Thank you. Our next question comes from the line of Jeff Jay of Daniel Energy Partners. Please go ahead.

Hey, guys. I had a quick follow-up on the AI optimization of artificial lift. I mean, you referenced savings in manpower and compression, but what about productivity uplifts from that?

Downtime minimization. Our teams are just doing a fantastic job controlling costs in somewhat of an inflationary environment. But the other side of that equation on the volume side, the technology is helping, but the responsiveness of our teams to managing the downtime and coupling that with the benefit you get from the AI, autonomous controls, has been a huge win for us.

And roughly how long do you think to get the remaining 1,000, you know, plunger-lift wells on line with this? Is it a matter of weeks, months, quarters?

Thank you, guys.

Thanks, Jeff.

Thank you. Our next question comes from the line of Betty Jung of Barclays. Your line is now open.

Hi. Good morning. Thank you for taking my question. Thank you. Appreciate all the comments earlier about the chemicals, EOR. Just a follow-up on that, where do you think you are in terms of understanding that technology and feeling comfortable about a broader deployment, and maybe just how much capital do you think will be appropriate to be putting into that technology right now?

Yeah, I mean, I think we just threw the first pitch, Betty. You know, this is like a Wolf Camp beef rack in Upton County in 2012, right, compared to where we are today. So I think our investors would like us to continue to spend capital here. It's not a huge dollar amount, you know, $50 to $100 million total across, you know, over $4 billion budget. But I think, you know, that capital will be well spent. And as we learn more, just like anything at Diamondback, if it works and gets better, it'll attract more capital.

Makes sense. And then for my follow-up, I want to ask about just the activity cadence and how to think about the normalized development program going forward. There's a lot of footage that came online in the last couple quarters, and then 4Q, at least based on the guidance, implied a lower completion quarter on a footage basis, and then through all that, oil is roughly flat. I know there's a lot of nuances that goes behind the lumpiness, maybe just how to think about how these periods fit together, maybe any lag between the till and the production contribution. And then how do you think about, like, will it be a normalized completion till cadence on a maintenance level basis?

Yeah, I mean, you know, I think the base case is run 19 to 20 rigs and run the five frack crews consistently. You know, I think that's where our head's at right now. And, you know, whether that spits out 120 tills in a quarter or 140 is just going to be dependent upon when those wells are popped. But in general, we're running a very level-loaded program that, you know, should spit out some organic growth.

Got it. Makes sense. Thank you.

Thank you. Our next question comes from the line of Gabe Dowd of Truist. Your line is now open.

Thanks, Operator, and thanks, guys. Thanks for taking my questions. I was hoping I could maybe follow up on Betty's question just on 27 and Kay's and earlier comment you made in the call around CapEx. So if you were to run the five crews through 27, is that the high end of 4Q's CapEx number, the 1050? Is that what we should expect for quarterly CapEx in 27, or is it a bit higher to get that low single-digit growth?

Yeah, I don't know. You know, Gabe, today, there's still a lot of variables out there. I'd probably say, you know, the $100 oil in the next few months.

Thank you. Our next question comes from the line of Arun Jayaram of J.P. Morgan. Your line is now open.

Yeah, good morning. Thanks for taking my question. I was wondering if we could go back to slide 11 and talk a little bit about Diamondbacks' results relative to the industry for the Barnett, because the gap relative to peers looks to be greater than for the kind of core Midland Basin programs. I was wondering if you could just make me comment on what you think the drivers of that. Is that better rock or what you're doing from a completion standpoint? And then maybe just talk a little bit about the planned shift in the full development mode. As you mentioned, I think the barn end is about 20% of drilling activities as we stand here today.

Yeah, Arun. I think just generally, the team had a very specific strategy on where they wanted to target. As I've said many times in this call, we're basin experts. We just think about this basin day in, day out, and we had a thesis that seems to be proving out in the geology, and I think that separation will continue.

Understood, understood. And then as a follow-up case, if you ran kind of five frat crews, 19 rigs or so in 2027, ballpark, how much footage would that kind of generate relative to the 6.4 million foot of completed lateral this year?

Yeah, I mean, relatively flat to this year, Arun.

Relatively flat. Okay. Great. I'll turn it back. Thank you. Thanks.

Thank you. Our next question comes from the line of Charles Mead of Johnson Rice. Your line is now open.

Good morning, Case, to you and your team, and I want to say I always enjoy your unvarnished comments in this format. Thanks, Charles. One quick follow-up on the Barnett. I think you mostly addressed this, but just one other dimension perhaps. It sounds like the big determinants of this productivity you're seeing are reservoir energy and the thickness, so you're choosing the best places. But is there anything else that has surprised you guys, or do those two factors explain most of this uplift that we're seeing?

I mean, I think geology drives the day, right, Charles? And, you know, we've picked some really good spots to get going here. I think we're learning the aerial extent of what's good. And, you know, I think if we take it back to 30,000 feet, you know, this is a play that was funded via, you know, Diamondbacks' cash flow and, you know, done at very low acreage prices and on a full cycle basis. This is probably one of the best investments we've ever made.

That's a good characterization. And in case this, I'm going to actually go out on a limb a little bit here, and so feel free to punt if you'd like. But your comments on the gas macro and saying that this is becoming more of a demand pull, the way I interpret that is it's kind of to put into phrases like, look, we're doing a B and a half a day without even trying. And so assuming you had the price signal and you wanted to try, what do you think you could grow your gas volumes by year over year? My first guess would be somewhere around 10% or 15%, which would be a doubling in like five or six years. But what would your guess be?

Yeah, I don't think that's a bad number. I think what we would need to see, though, and need to control is more of the value chain, right? So it's not just what you're receiving at the wellhead. It's, you know, what's the processing cost? What's your cost to, you know, move it down the pipe? And then what's, you know, a buyer buying it at? So, you know, I think we're probably still a long way from drilling for gas specifically. I think it's naturally just going to happen. But, you know, if you were to drill for gas specifically out of this basin, you've got to think more like a gas company that has more of the value chain under their control.

That's great detail. Thank you, Case. Appreciate it.

Thanks, Charles.

Thank you. Thank you. Our last question comes from the line of Leo Mariani of Roth. Your line is now open.

Hey, guys. I wanted to follow up on the comments just around approved recoveries. Obviously, you're talking about roughly 10% currently. Do you think you can actually move the needle on that number where it actually goes, like, say, closer to 11? Is that a this-decade event, or do you think of that as more of something that could happen in, say, the first part of the 2030s?

I mean, I think 11 is achievable in the next couple of years. How do you get from 10 to 20? Obviously, a much larger oil company has talked about that in this basin, and I think there's probably some use cases that are working in a lab or early tests in the field that give me some hope that that's probably possible in the next decade. But, you know, I think strategy-wise, Leo, we have the longest duration inventory in the basin at the lowest cost structure. So we're going to be the last company that has to try this stuff. And if this stuff, you know, these methodologies become better rate of return than what we have left to drill, then we'll pivot to allocating more capital to them. But I think what we've built inside the business is the most flexibility to try these things or have to do these things last versus try them and learn from them today.

Okay, that certainly makes sense. And then just to kind of be clear on your comments just around, you know, thoughts going forward, I mean, presumably you're still in fully in green light mode here today, you know, at this point in time. I know 27 is TBD, but at least for now, it doesn't seem like there's anything that's moving you guys off green light in the near term.

Yeah, that's right. I mean, it's been a couple months or a couple quarters since the stoplight went into still in the green light.

Okay. Thanks, guys.

Thank you.

Thank you. This concludes the question and answer session. I would now like to turn it back to Kay Spenthoff, CEO for Closing Remarks.

Thank you for the time. New record, 65 minutes, and I appreciate everyone making the effort. So thank you for your interest, and we're available to answer any questions if you have any.

Thank you for your participation in today's conference. This does conclude the program, and you may now disconnect.